Method and Apparatus for Testing the Blowout Preventer (BOP) on a Drilling Rig

ABSTRACT

A method and apparatuses for testing the blowout preventer (BOP) piping system on a drilling rig for leaks. The method and apparatuses can be used in conjunction with a pressure or volumetric method to more accurately test the BOP for integrity and to shorten the total time of testing.

RELATED APPLICATIONS

This application is a continuation of U.S. patent application Ser. No.16/228,230, filed Dec. 20, 2018, which is a continuation of U.S. patentapplication Ser. No. 14/545,476 filed May 8, 2015, now U.S. Pat. No.10,161,240, which claims the benefit of U.S. Provisional PatentApplication Ser. No. 61/990,508 filed May 8, 2014, all of which areincorporated by reference herein.

BACKGROUND OF THE INVENTION Field of the Invention

A method and apparatuses for testing the blowout preventer (BOP) pipingsystem on a drilling rig for leaks. The method and apparatuses arecomprised of a pressure, or alternatively a volumetric system, to testthe piping and flanges for integrity and an acoustic sensor system toverify that the valves isolating the system for the integrity testingare completely sealed. The use of an acoustic valve sensing system withan integrity test minimizes the number of false alarms due to flowacross an incompletely sealed valve and reduces the time to mitigatethese false alarms.

Brief Description of Prior Art

Currently, regulations in the United States (Title 30: MineralResources, Part 250—Oil And Gas and Sulphur Operations in the OuterContinental Shelf Subpart D—Oil and Gas Drilling Operations; § 250.447-§250.451) require that the BOP system on a drilling rig, both onshore andoffshore rigs, be pressure tested according to Part 250, Subpart D,Sections 250.447-250.45. Section 250.447 indicates that the BOP shouldbe tested when installed or at least every 14 days. Section 250.448indicates that the BOP must be pressure tested. The pressure test isdesigned to insure that all parts of the BOP are operationallyfunctional, i.e., pipes and flanges do not leak and valves sealcompletely when closed so that there is no flow across the valve. Theregulation indicates that when a pressure test of the BOP system isperformed, each component of the BOP must be pressure tested at alow-pressure and at a high-pressure. The low-pressure test must beconducted before the high-pressure test. Each individual pressure testmust hold pressure long enough to demonstrate that the testedcomponent(s) holds the required pressure. The required test pressuresare as follows:

(a) Low-pressure test. All low-pressure tests must be between 200 and300 psi. Any initial pressure above 300 psi must be bled back to apressure between 200 and 300 psi before starting the test. If theinitial pressure exceeds 500 psi, then the test must be re-initiatedafter bleeding the pressure back to zero.(b) High-pressure test for ram-type BOPs, the choke manifold, and otherBOP components. The high-pressure test must equal the rated workingpressure of the equipment or be 500 psi greater than the calculatedmaximum anticipated surface pressure (MASP) for the applicable sectionof hole. Approval of the District Manager is required before the BOPequipment is tested to the MASP plus 500 psi.(c) High pressure test for annular-type BOPs. The high pressure testmust equal 70 percent of the rated working pressure of the equipment orto a pressure approved in your APD.(d) Duration of pressure test. Each test must hold the required pressurefor 5 minutes. For surface BOP systems and surface equipment of a subseaBOP system, a 3-minute test duration is acceptable if the test pressuresare recorded. If the equipment does not hold the required pressureduring a test, then the problem must be corrected and the affectedcomponents must be retested.

FIG. 1a illustrates a BOP Stack that needs to be pressure tested[http://www.drillingdoc.com/bop-test-procedure/]. It is comprised of theBOP itself, short sections of piping, and valves used to isolate partsof the BOP system. Many of the valves are in pairs for redundancy.Valves are opened and closed to test each part of the entire system.This procedure illustrates a five test procedure and involves a CasingPressure Test, a Pipe Rams Test, an Annular Test, a Blind Rams Test, anda Choke Manifold Test. Such BOP tests can involve many more valves andmany more than five valve configurations.

Typically, the BOP system is tested for leaks by closing valves on theBOP system to isolate parts or all of the BOP for this testing andpressurizing the system with water. Any drop in pressure that exceedssome specified threshold value is indicative of an integrity problem.This pressure drop can be produced by a leak in a pipe or pipe flange,and/or it could be produced by flow across an incompletely closed valve.Any valves that do not completely seal can be mistaken for a leak (i.e.,a false alarm) or prevent an integrity test from being completed. Tomitigate these false alarms and incompletely sealed valves can be anextremely time-consuming and expensive process, because, first, it mustbe determined that a valve is not sealed and is the source of thepressure drop rather than a leak from a pipe flange, and second, if thepressure drop is due to an incompletely closed valve, then it must bedetermined which valve or valves are not sealed. Before the valves areconsidered, a visual check of the piping, piping flanges, andappurtenances is made to determine if there are any obvious leaks. Ifnone are found, then the valves are checked. The present testingprocedures do not include any sensing systems to check whether or notthe valves are sealed. If a pressure loss occurs, then all of the valvesare checked to insure they are closed, but this is a challenging taskand is generally done by either re-opening and re-closing each valve tomake sure they are closed and/or further tightening each valve. This istime consuming, because the only way to determine whether or not thevalve check was successful was to repeat the pressure test. Simplyreclosing the valve or more tightly closing the valve is no assurancethat the valve is actually closed, because debris, grit, sand, and nicksin the valve may prevent a complete seal.

An acoustic sensor can be attached to the external wall of the pipe neareach valve (either permanently or temporarily) to listen for the “flownoise” produced by the flow across an incompletely closed valve with asmall hole or slit (i.e., the valve flow signal). This approach will notwork well, because there are a variety of sources of background noisepresent on a drilling rig that cannot be easily or safely eliminated andthat could easily mask the valve flow signal. There are several types ofbackground noise. One type is background noise that emanates from asingle location or a single source. This can not only mask the valveflow signal, but it can also be mistaken for a valve flow signal or aleak. A generator or a pump would be examples of this type of noise.These sources of noise can be very large, much larger than the valveflow signal to be detected. Fortunately, the acoustic return from mostof these sources of noise are found in one or more narrow frequencybands that are generally not found in the same frequency bands as thevalve flow signal, and thus, they can be removed through advanced signalprocessing methods, as described as part of the processing methods ofthe present invention. The noise cancellation methods (both adaptivenoise cancellation and average background transfer function noisecancellation) of the present invention can also address the morecomplicated sources of background noise that are also present in thevalve flow signal band. In general, simple acoustic listening systems donot have and do not use noise cancellation or advanced signal processingmethods as described herein and none are currently used as part of BOPtesting.

Another type of background noise is broadband noise that occurs at allfrequency bands, including the valve flow signal bands. If this level ofnoise is larger than the valve flow signal or a leak, it can mask thevalve flow signal or a leak, and as indicated above, acoustic listeningmethods will not work, unless advanced signal processing is used.

BOP testing requires that all drilling operations be shut down untilthese tests are completed and the integrity of the entire BOP system canbe verified. This includes all valves, piping, and connections. Becauseof the large number of valves that need to be checked and that need tobe sealed, the total BOP is not usually tested at one time. Instead,different parts of the BOP piping system are individually tested.Furthermore, because of the integrity of the BOP system must be ensuredat the working operational pressure, more than one pressure test istypically required. For safety, a first pressure test is required to beconducted at a lower pressure (e.g., 200 to 300 psig) to ensure that thesystem is ready to be tested at the working operational pressures (e.g.,5,000 psig, or higher), or at a minimum of 500 psig. While the samevalve problems can exist at both pressures, many of the improperlysealed valves can be mitigated at the lower pressure before testing atthe higher pressure, which is safer and more efficient. One companyrequires testing nine different piping and valve configurations to fullyassess the integrity of a BOP system. Typically, the pressure testingprocedure is performed manually, is highly operator dependent forpreparation of the BOP for testing and for interpretation of theresults, and may take between 6 h and 40 hours to complete, with anaverage test time of 14 h. Since the piping sections are short (e.g.,typically less than 100 ft), leaks are verified by visual inspection.This can be a challenging problem if the leaks are small or if tests aredone at night or in inclement weather. Valve closure problems are evenmore difficult to resolve. This testing represents a loss of totaloperational drilling time of between 2 and 12% with an average of 4%.Because of this testing significantly impacts operations and results ina loss of income, quicker methods of testing are needed.

The method and apparatuses of the present invention are motivated by theneed to reduce the drilling rig downtime associated with the periodictesting of the BOP piping system. The method and apparatuses of thepresent invention can address this downtime problem by integrating anacoustic valve sensing system as part of the total integrity pressuretest. Knowing that each valve is sealed, or knowing which valve orvalves are not sealed, and by verifying that all valves are sealedbefore beginning a test, results in a significant time savings, and morereliable test results. The use of an acoustic valve sensing system hasthe potential to significantly reduce the down time associated with thecurrent testing approach. The use of such acoustic systems, however, isnot currently being done as part of the pressure test.

Acoustic systems have been used for many years to determine whether ornot a valve is “leaking” (i.e., not fully closed or sealed) in a varietyof applications. In general, this approach requires a listening approachusing a single acoustic sensor or stethoscope placed on the valve ornearby piping. In addition, acoustic systems have been used for manyyears to find leaks in pipes and to locate those leaks in pipes usinglistening methods or cross correlation methods. One company uses acoherence function method, because it identifies the frequency bandswith the maximum signal-to-noise ratio (SNR), single propagation modes,and propagation velocity. However, acoustic measurement systems forverifying valve closure have not been used or integrated together with aconstant-pressure volumetric leak detection system when testing a BOPSystem for integrity, where a volumetric system can be used to quantifythe flow rate across an incompletely seal valve.

SUMMARY OF THE INVENTION

It is the object of this invention to provide a method and apparatusesfor testing the BOP system on a drilling rig for integrity.

It is the object of this invention to provide a method and apparatusesfor testing the BOP system on a drilling rig for integrity with a methodand apparatuses for verifying that the valves are completely closed whentesting the BOP system or when isolating that portion of the BOP systembeing tested for integrity.

It is the object of this invention to provide a method and apparatusesfor pressure testing the BOP system on a drilling rig for integrity.

It is the object of this invention to provide a method and apparatusesfor volumetrically testing the BOP system on a drilling rig forintegrity.

It is the object of this invention to provide a method and apparatusesfor verifying that the valves closed to isolate and pressurize thatportion of the BOP system being integrity tested are completely closed.

It is the object of this invention to provide a method and apparatusesfor verifying that the valves closed to isolate and pressurize thatportion of the BOP system being integrity tested are completely closed,and if not, to determine which valve or valves are not completelyclosed.

It is the object of this invention to provide a method and apparatusesfor verifying that the valves closed to isolate and pressurize thatportion of the BOP system being integrity tested are completely closed,and if not, to determine the flow rate from the valve or valves that arenot completely closed.

The preferred embodiment of the present invention is comprised of (1) apressure testing system to test the BOP system or portions of the BOPsystem for integrity and (2) an acoustic valve measurement system todetermine whether or not each valve that is closed for the pressure testis actually completely closed. The pressure testing system is used totest the BOP system or portions of the BOP system for integrity afterverifying with an acoustic measurement system that all of the valvesclosed to isolate and pressurize that portion of the BOP system beingtested are completely closed, and if not, to identify which valves arenot completely closed and need to be closed to perform a test. As analternative embodiment, a constant-pressure, volumetric measurementsystem can be used in conjunction with the acoustic system to quantifythe flow across a valve that is not closed and to verify that the flowrate is zero when the valve is believed to be closed. If the measuredflow is due to an incompletely closed valve, then this flow will bedecreased or eliminated as the valve is more completely closed. Becausea constant-pressure volumetric system can detect smaller flows than anacoustic system, the use of the volumetric system with the acousticsystem further reduces the number of false alarms due to incompletelyclosed valves over that of an acoustic system alone. Theconstant-pressure, volumetric system will also detect any residual flownot associated with an incompletely sealed valve, and as an alternativeembodiment, a constant-pressure volumetric testing system can be usedinstead of a pressure testing system for testing a portion or all of theBOP system for leaks. In this test, the pressure is maintained at thetest pressure and the volume changes, which would result in a pressuredrop, are measured directly and can be converted to an equivalentpressure drop, if necessary.

The acoustic valve measurement system provides a method to allow the BOPsystem to be pressure tested (or volumetrically tested) more efficientlyand may reduce the number of pressure tests into sub-configuration thatis currently required to complete a test of the entire BOP system,because the potential of a failed pressure test due to one or moreincompletely sealed valves can be identified and minimized or eliminatedbefore a test is performed.

As illustrated for a simple pipe and valve configuration in FIG. 2, thepreferred embodiment of the valve measurement system is comprised of twoacoustic sensors mounted on the outside of the pipe with one sensor oneither side of the valve. Acoustic sensors 1 and 2 are preferred, butacoustic sensors 3 and 2 will also work well. In addition, acousticsensors 1 and 3, although they do not bracket the valve can also beused. As an alternative embodiment, the valve measurement system can beimplemented with only one acoustic sensor positioned close enough to avalve that is not completely closed to detect any flow noise produced bythat valve, but if flow noise from a valve is detected, it is notpossible to say with certainty that it is the valve closest to theacoustic sensor that is not completely closed. With two or more acousticsensors, where at least one acoustic sensor is located on either side ofthe valve, a definitive statement about the status of the valve that isbracketed by the acoustic sensors can be made, because the source of thevalve flow signal can be “located” between the two sensors. In addition,the signal-to-noise ratio (SNR) of the two-valve acoustic system issignificantly higher than a one-valve acoustic system. An accuratelocation estimate indicates that the bracketed valve is producing thevalve flow signal. Once this bracketed valve is closed, another acoustictest will determine if other valves may also be incompletely closed. Asanother alternative embodiment, a third or fourth acoustic sensor can bemounted on the piping leading into the valve but at a known separationdistance from each sensor bracketing the valve. The two acoustic sensorson each side of the valve (not bracketing the valve) can be used todetect a valve flow and to compute the velocity of the flow noisepropagating through the piping, which leads to more accurate location ofthe valve between the two acoustic sensors bracketing the valve. Theycan also be used to determine from which direction a valve flow signalis coming from. To compute the propagation velocity requires that thedistance between the acoustic sensors be known. The most reliableverification that a valve with bracketing acoustic sensors is completelysealed requires that the distance between two acoustic sensorsbracketing the valve and from each sensor to the valve be known.However, such verification can also be accurately performed withoutknowing these distances.

The preferred embodiment detects any flow across the valve by computingthe cross power spectrum when the BOP is pressurized and dividing thiscross power spectrum by the cross power spectrum of the background noisethat is obtained when the pressure across the valve is the same,generally at 0 psig, or when the valve is known to be completely closedas ascertained by another test like a volumetric test.

IN THE DRAWINGS

FIGS. 1a and 1b illustrate a test configuration for a BOP System withnumerous valves that need to be pressure tested to verify that they canbe completely closed [http://www.drillingdoc.com/bop-test-procedure/].FIG. 1a illustrates a BOP Stack that needs to be tested, and FIG. 1billustrates the valve configuration for a Casing Pressure Test, which isone of five tests for this BOP Stack configuration.

FIG. 2 illustrates a section of the testing configuration for a BOPTest.

FIG. 3 illustrates Configuration 1 with One Acoustic Sensor to check forthe valve flow signal (VFS).

FIG. 4 illustrates Configuration 2 with One Acoustic Sensor to check forthe valve flow signal and an independent Reference Acoustic Sensor (REF)to measure Background Noise.

FIG. 5 illustrates Configuration 3 with One Acoustic Sensor to checkboth for the valve flow signal (VFS) and to measure Background Noise(REF).

FIG. 6 illustrates Configuration 4 with Two Acoustic Sensors, both onthe same side of the Valve.

FIG. 7 illustrates Configuration 5 with Two Acoustic Sensors, where thetwo sensors bracket the Valve.

FIG. 9 illustrates Configuration 6 with Three Acoustic Sensors, whereSensors 1 and 2 bracket the Valve and are used to Locate the Valve FlowSignal (VFS), and Sensors 1 and 3 are on the same side of the Valve andare used to measure the propagation velocity of the Valve Flow Signal(VFS).

FIG. 10 illustrates Configuration 6 with Two Acoustic Sensors, where thetwo sensors bracket the Valve, and are used to locate the position ofthe Valve relative to the REF Acoustic Sensor.

FIG. 11 illustrates a schematic of the PALS.

FIG. 12 illustrates the test configuration 2 on the test pipeline withacoustic sensors mounted to the line with epoxy. The distance betweenthe reference and velocity sensors was 137.3 ft and the distance betweenthe reference and the position sensors was 360.0 ft. The leak was 233.5ft from the reference sensor.

FIG. 13 illustrates the output of the PALS given (1) the sensorconfiguration shown in FIG. 12, with REF2, VEL, position=POS=360.0 ft;(2) a leak of 1.9 gal/h at 70 psi, through a 0.01-in.-diameter hole inthe pipeline; and (3) a distance of 360.0 ft between the two sensorsbracketing the leak. The reference sensor was mounted on the blindflange at the top of the pipe.

Upper portion: Output showing the position of the leak and the velocityof the leak signal determined by the coherence function. The leak waslocated to within 0.4 ft of its actual position—less than 0.1% of thedistance between the two sensors bracketing the leak. (The PALS measuredthe leak's position at 233.5 ft from the reference sensor; the actualposition was 233.1 ft.) The estimate of the leak's position wasdetermined from a measurement of the propagation velocity of the leaksignal (1,409 m/s) made at the same time.Lower portion: Output showing the position of the leak and the velocityof the leak signal as determined by the correlation function (using thefrequency band determined by the coherence function). The leak waslocated to within 2.5 ft of its actual position-0.7% of the distancebetween the two sensors bracketing the leak. (The PALS measured theleak's position at 236 ft from the reference sensor; the actual positionwas 233.5 ft.) The leak's position was determined from a measuredestimate of the propagation velocity of the leak signal (1,409 m/s) madewith the coherence function.

FIG. 14 illustrates the output of the PALS given the sensorconfiguration shown in FIG. 12 (REF2, VEL, Position=POS=360.0 ft) and adistance of 360.0 ft between the sensors that bracket the leak.

Upper Portion: The output of the coherence function over the frequencyband from 0 to 19.2 kHz is typical of a test of background noise when noleak is present.Lower Portion: The output of the correlation function over the frequencyband from 0 to 19.2 kHz is typical of a test for background noise whenno leak is present.

FIG. 15 illustrates the test configuration 1, with acoustic sensorsmounted to the line with epoxy. The distance between the reference andvelocity sensors was 63.2 ft and the distance between the reference andthe position sensors was 159.5 ft. The leak was 33.0 ft from thereference sensor.

FIG. 16 illustrates the output of the PALS for the sensor configurationshown in FIG. 15 (Ref 1-Vel-Pos=159.5 ft) and a leak through a0.01-in.-diameter hole (1.9 gal/h) with the sensors bracketing the leakseparated by 159.5 ft (Edison STPF on 8/15/00 at 15:29). The leak waslocated to within 0.5 ft (0.3% of the sensor separation distance) of itsactual position. The actual position of the leak was 33.0 ft from thereference sensor, and the measured position was 33.5 ft from thereference sensor. The position estimate was determined using a measuredestimate of the propagation velocity (1,631 m/s) made at the same time.The output shows the position and velocity determined by the coherencefunction.

FIG. 17 illustrates a schematic of the 25-ft, 2-in.-diameter steel pipesection. The valve was located 12.5 ft from either end of the pipe. Thefar and near sensors were mounted at 8.5 ft and 3.4 ft respectively fromthe valve.

FIG. 18 illustrates the coherence function (magnitude squared) developedfrom a 2-min test with no valve leak (valve cracked but no pressuredifference across the valve) for the sensor configuration shown in FIG.17.

FIG. 19 illustrates the power spectra developed from a 2-min test withno valve leak (valve cracked but no pressure difference across thevalve) for the sensor configuration shown in FIG. 17.

FIG. 20 illustrates the coherence function developed from a 2-min testwith a valve leak of 0.16 gal/h for the sensor configuration shown inFIG. 17.

FIG. 21 illustrates the power spectra developed from a 2-min test with avalve leak of 0.16 gal/h for each of the acoustic sensors shown in FIG.17.

FIG. 22 illustrates the valve flow measurement laboratory testconfiguration to illustrate the preferred methods of analysis to detectflow across the valve in the center of the pipe. As illustrated two ofthe acoustic sensors are mounted on the valve flange and one is on theleft side of the pipe.

FIG. 23 illustrates the valve flow measurement laboratory testconfiguration to illustrate the preferred methods of analysis with twoof a number of acoustic sensor locations used in the analyses. The POSacoustic sensor is 0.375 ft (4.5 in.) from the valve and the REFacoustic sensor is located on the opposite of the valve at a distance of0.375 ft (4.5 in.) from the valve. A third acoustic sensor, the VELsensor is located on the same side of the valve as the REF sensor and1.5 ft (18 in.) away from the REF sensor. The REF sensor is 0.75 ft (9in.) away from the POS sensor. This configuration was used in theanalyses illustrated in FIGS. 24 through 55.

FIG. 24 illustrates the time series of the POS and the REF acousticsensors when the valve is partially closed but the pressure on bothsides of the valve is 0 psig. Only background noise is observed. Theresults would be the same if the valve were totally opened, totallyclosed, or at the same pressure on both sides of the valve.

FIG. 25 illustrates the PSDs of the POS and the REF acoustic sensors forthe time series in FIG. 24 when the valve is partially closed but thepressure on both sides of the valve is 0 psig. Only background noise isobserved. The results would be the same if the valve were totallyopened, totally closed, or at the same pressure on both sides of thevalve.

FIG. 26 illustrates the cross PSD of the POS and REF acoustic sensorsthat were computed from the time series of the acoustic sensors when thevalve is partially closed but the pressure on both sides of the valve is0 psig. Only background noise is observed. The results would be the sameif the valve were totally opened, totally closed, or at the samepressure on both sides of the valve.

FIG. 27 illustrates the output of the coherence function for thebackground time series in FIG. 24.

FIG. 28 illustrates the output of the cross correlation function for thebackground time series in FIG. 24 without bandpassing and withbandpassing.

FIG. 29 illustrates the time series of the POS and the REF acousticsensors when the valve is partially closed but the pressure on one sideof the valve is at 100 psig and the pressure on the opposite side of thevalve is 0 psig. The presence of the valve flow signal is observed andis obviously different than the response when the pressure is zero onboth sides of the valve.

FIG. 30 illustrates the PSDs of the POS and the REF acoustic sensors forthe time series in FIG. 29 when the valve is partially closed but thepressure on one side of the valve is at 100 psig and the pressure on theopposite side of the valve is 0 psig. The presence of the valve flowsignal is observed and is obviously different than the response when thepressure is zero on both sides of the valve.

FIG. 31 illustrates the PSDs of the POS and the REF acoustic sensors forthe time series in FIG. 33 of the valve flow signal relative to the timeseries in FIG. 24 of the background noise.

FIG. 32 illustrates the cross PSD of the POS and REF acoustic sensorsthat were computed from the time series of the acoustic sensors when thevalve is partially closed but the pressure on one side of the valve isat 100 psig and the pressure on the opposite side of the valve is 0psig. The presence of the valve flow signal is observed and is obviouslydifferent than the response when the pressure is zero on both sides ofthe valve.

FIG. 33 illustrates the output of the coherence function for a 5.3-gal/hleak with no generator for the time series in FIG. 29.

FIG. 34 illustrates the output of the cross correlation function for a5.3-gal/h leak with no generator for the time series in FIG. 24 withbandpassing.

FIG. 35 illustrates the (a) time series of the POS acoustic sensorcomparing the background noise in FIG. 24 and the valve flow signal inFIG. 29 and the (b) time series of the REF acoustic sensor comparing thebackground noise in FIG. 24 and the valve flow signal in FIG. 29.

FIG. 36 illustrates the ratio or SNR of the PSDs of the POS and the REFacoustic sensors when the valve flow signal is present and when it isnot.

FIG. 37 illustrates the ratio or SNR of the cross PSD of the POS and REFacoustic sensors when the valve flow signal is present and when it isnot.

FIG. 38 illustrates the difference of the PSDs of the POS and the REFacoustic sensors when the valve flow signal is present and when it isnot.

FIG. 39 illustrates the difference of the cross PSD of the POS and REFacoustic sensors when the valve flow signal is present and when it isnot.

FIG. 40 illustrates the time series of the POS and the REF acousticsensors in the presence of generator noise when the valve is partiallyclosed but the pressure on both sides of the valve is 0 psig. Onlybackground noise is observed. The results would be the same if the valvewere totally opened, totally closed, or at the same pressure on bothsides of the valve.

FIG. 41 illustrates the PSDs of the POS and the REF acoustic sensors inthe presence of generator noise for the time series in FIG. 40 when thevalve is partially closed but the pressure on both sides of the valve is0 psig. Only background noise is observed. The results would be the sameif the valve were totally opened, totally closed, or at the samepressure on both sides of the valve.

FIG. 42 illustrates the cross PSD of the POS and REF acoustic sensors inthe presence of generator noise that were computed from the time seriesof the acoustic sensors when the valve is partially closed but thepressure on both sides of the valve is 0 psig. Only background noise isobserved. The results would be the same if the valve were totallyopened, totally closed, or at the same pressure on both sides of thevalve.

FIG. 43 illustrates the output of the coherence function for thebackground time series in the presence of generator noise in FIG. 40.

FIG. 44 illustrates the output of the cross correlation function for thebackground time series in the presence of generator noise in FIG. 40with bandpassing.

FIG. 45 illustrates the time series of the POS and the REF acousticsensors in the presence of generator noise when the valve is partiallyclosed but the pressure on one side of the valve is at 100 psig and thepressure on the opposite side of the valve is 0 psig. The presence ofthe valve flow signal is observed and is obviously different than theresponse when the pressure is zero on both sides of the valve.

FIG. 46 illustrates the PSDs of the POS and the REF acoustic sensors inthe presence of generator noise for the time series in FIG. 45 when thevalve is partially closed but the pressure on one side of the valve isat 100 psig and the pressure on the opposite side of the valve is 0psig. The presence of the valve flow signal is observed and is obviouslydifferent than the response when the pressure is zero on both sides ofthe valve.

FIG. 47 illustrates the PSDs of the POS and the REF acoustic sensors forthe time series in FIG. 45 of the valve flow signal relative to the timeseries in FIG. 40 of the background noise.

FIG. 48 illustrates the cross PSD of the POS and REF acoustic sensors inthe presence of generator noise that were computed from the time seriesof the acoustic sensors when the valve is partially closed but thepressure on one side of the valve is at 100 psig and the pressure on theopposite side of the valve is 0 psig. The presence of the valve flowsignal is observed and is obviously different than the response when thepressure is zero on both sides of the valve.

FIG. 49 illustrates the output of the coherence function for a leak rateof 4.05 gal/h in the presence of generator noise in the time series ofFIG. 45.

FIG. 50 illustrates the output of the cross correlation function for aleak rate of 4.05 gal/h in the presence of generator noise for the timeseries in FIG. 45 with bandpassing.

FIG. 51 illustrates the (a) time series of the POS acoustic sensorcomparing the background noise in FIG. 40 and the valve flow signal inFIG. 45 and the (b) time series of the REF acoustic sensor comparing thebackground noise in FIG. 40 and the valve flow signal in FIG. 45.

FIG. 52 illustrates the ratio or SNR of the PSDs of the POS and the REFacoustic sensors in the presence of generator noise when the valve flowsignal is present and when it is not.

FIG. 53 illustrates the ratio or SNR of the cross PSD of the POS and REFacoustic sensors in the presence of generator noise when the valve flowsignal is present and when it is not.

FIG. 54 illustrates the difference of the PSDs of the POS and the REFacoustic sensors in the presence of generator noise when the valve flowsignal is present and when it is not.

FIG. 55 illustrates the difference of the cross PSD of the POS and REFacoustic sensors in the presence of generator noise when the valve flowsignal is present and when it is not.

FIG. 56 illustrates another valve flow measurement laboratory testconfiguration used to illustrate the preferred methods of analysis. ThePOS acoustic sensor is 1.83 ft (22 in.) from the valve. The REF acousticsensor is located on the opposite of the valve at a distance of 2.0 ft(24.0 in.) from the valve. A third acoustic sensor, the VEL sensor islocated on the same side of the valve as the REF sensor and 0.5 ft (6in.) away from the REF sensor and 1.5 ft (18 in. from the valve. The REFsensor is 3.33 ft (40 in.) away from the POS sensor. This configurationwas used in the analyses illustrated in FIGS. 57 through 72 without thegenerator turned on.

FIG. 57 illustrates the time series of the POS and the REF acousticsensors when the valve is partially closed but the pressure on bothsides of the valve is 0 psig. Only background noise is observed. Theresults would be the same if the valve were totally opened, totallyclosed, or at the same pressure on both sides of the valve.

FIG. 58 illustrates the PSDs of the POS and the REF acoustic sensors forthe time series in FIG. 57 when the valve is partially closed but thepressure on both sides of the valve is 0 psig. Only background noise isobserved. The results would be the same if the valve were totallyopened, totally closed, or at the same pressure on both sides of thevalve.

FIG. 59 illustrates the cross PSD of the POS and REF acoustic sensorsthat were computed from the time series of the acoustic sensors when thevalve is partially closed but the pressure on both sides of the valve is0 psig. Only background noise is observed. The results would be the sameif the valve were totally opened, totally closed, or at the samepressure on both sides of the valve.

FIG. 60 illustrates the output of the coherence function for thebackground time series in FIG. 57.

FIG. 61 illustrates the output of the cross correlation function for thebackground time series in FIG. 57 without bandpassing and withbandpassing.

FIG. 62 illustrates the time series of the POS and the REF acousticsensors when the valve is partially closed but the pressure on one sideof the valve is at 100 psig and the pressure on the opposite side of thevalve is 0 psig. The presence of the valve flow signal is observed andis obviously different than the response when the pressure is zero onboth sides of the valve.

FIG. 63 illustrates the PSDs of the POS and the REF acoustic sensors forthe time series in FIG. 62 when the valve is partially closed but thepressure on one side of the valve is at 100 psig and the pressure on theopposite side of the valve is 0 psig. The presence of the valve flowsignal is observed and is obviously different than the response when thepressure is zero on both sides of the valve.

FIG. 64 illustrates the PSDs of the POS and the REF acoustic sensors forthe time series in FIG. 62 of the valve flow signal relative to the timeseries in FIG. 57 of the background noise.

FIG. 65 illustrates the cross PSD of the POS and REF acoustic sensorsthat were computed from the time series of the acoustic sensors when thevalve is partially closed but the pressure on one side of the valve isat 100 psig and the pressure on the opposite side of the valve is 0psig. The presence of the valve flow signal is observed and is obviouslydifferent than the response when the pressure is zero on both sides ofthe valve.

FIG. 66 illustrates the output of the coherence function for thebackground time series in FIG. 57.

FIG. 67 illustrates the output of the cross correlation function for thebackground time series in FIG. 57 without bandpassing and withbandpassing.

FIG. 68 illustrates the (a) time series of the POS acoustic sensorcomparing the background noise in FIG. 57 and the valve flow signal inFIG. 62 and the (b) time series of the REF acoustic sensor comparing thebackground noise in FIG. 57 and the valve flow signal in FIG. 62.

FIG. 69 illustrates the ratio or SNR of the PSDs of the POS and the REFacoustic sensors when the valve flow signal is present and when it isnot.

FIG. 70 illustrates the ratio or SNR of the cross PSD of the POS and REFacoustic sensors when the valve flow signal is present and when it isnot.

FIG. 71 illustrates the difference of the PSDs of the POS and the REFacoustic sensors when the valve flow signal is present and when it isnot.

FIG. 72 illustrates the difference of the cross PSD of the POS and REFacoustic sensors when the valve flow signal is present and when it isnot.

DESCRIPTION OF THE PREFERRED EMBODIMENT

The regulation Part 250—Oil And Gas and Sulphur Operations in the OuterContinental Shelf Subpart D—Oil and Gas Drilling Operations; § 250.447-§250.451) require that the BOP systems in the United States (Title 30:Mineral Resources, on a drilling rig for both onshore and offshore rigsbe pressure tested according to Part 250, Subpart D, Sections250.447-250.45. The pressure test is designed to insure that all partsof the BOP are operationally functional, i.e., pipes and flanges do notleak and valves seal completely when closed so that there is no flowacross the valve.

To test the BOP for integrity safely and/or in accordance with BOPregulations, a pressure testing system, or its alternative, aconstant-pressure, volumetric testing system needs to be performed attwo pressures. For safety and efficiency, a test should be performed ata lower pressure (e.g., between 200 and 300 psig) to verify that thesystem passes before raising the pressure to higher pressures (e.g.,typically 5,000 psig, or more) for a test at the working operationalpressure of the drilling rig. This two-pressure testing approach is donefor safety, efficiency, and effectiveness. Because the test media iswater, the pressures are high, and the volume of the pressurized liquidis small, the impact of temperature-induced pressure (and/or volumetric)changes are small and can, to first order, be neglected. In addition,short tests (e.g., 5 to 10 min) can be performed. The total timerequired to perform an integrity test and the accuracy of the integritytest can be significantly impacted by whether or not the valves arecompletely closed so that small flows across an incompletely sealedvalve do not produce pressure (and/or volumetric) changes that providefalse indications of a leak or a system integrity problem. The additionof and the integration of a valve measurement system with a pressure(and/or a volumetric) integrity testing system reduces the total testtime and increases the accuracy and reliability of the integrity test.

FIGS. 1a and 1b illustrate a BOP system that needs to be tested. Acomplete pressure test is accomplished by partitioning the BOP systeminto five or more different pipe and valve configurations. Ourvalidation testing was performed on a drilling rig that required ninedifferent pipe and valve configurations. The piping typically rangesfrom 3 to 6 in. in diameter and is typically less than 100 ft betweenvalves. The BOP tree is shown in the middle of the figure. Over 12 gatevalves are shown in this BOP system. FIG. 1b illustrates the valveconfiguration for a Casing Pressure Test. This BOP system testillustrates a five-subsystem test procedure and involves a CasingPressure Test, a Pipe Rams Test, an Annular Test, a Blind Rams Test, anda Choke Manifold Test [http://www.drillingdoc.com/bop-test-procedure/].Two pressure tests, one at the low pressure and one at the high pressuremust be performed. Such BOP tests can involve many more valves and manymore than five valve configurations. This approach is taken to insurethat each valve and pipe section of the BOP system is tested and tolimit the number of valves in each test configuration so that thesources of false alarms (i.e., one or more valves that prevent passingthe pressure test because of one or more incompletely closed or sealedvalves) can be more easily identified and mitigated. In order topressure test the configuration illustrated in FIG. 1b , five valvesmust completely seal. If any of these valves fail to seal completelywhen closed, there will be a small flow from the pipe on one side of thevalve to the pipe on the other side of the valve. This loss of volumedue to the flow across the valve will result in a pressure drop, and iflarge enough, will be responsible for not passing the pressure test.Once a pressure test fails, the operators visually examine the pipingand the flanges for leaks. If not are found, then it is assumed that oneor more of the valves are not completely closed, but the challenge is todetermine which one or more valves are not sealed. Typically, the valvesare more tightly closed or re-opened and re-closed, and a secondpressure test is performed. This is time consuming and there is noguarantee that the culprit valves are sealed in the second test and thatvalves that were completely closed in the first test actually seal inthe second test. Experience has shown that it can be very time consumingto perform a test of the entire BOP system because of the large numberof valves that must be completely sealed to complete a valid pressuretest.

The preferred embodiment of the present invention is comprised of (1) apressure testing system to test the BOP system or portions of the BOPsystem for integrity and (2) an acoustic valve measurement system todetermine whether or not each valve that is closed for the pressure testis actually completely closed. The pressure testing system is used totest the BOP system or portions of the BOP system for integrity afterverifying with an acoustic measurement system that all of the valvesthat are closed to isolate and pressurize that portion of the BOP systembeing tested are completely closed, and if not, to identify which valvesare not completely closed and need to be closed to perform a test. As analternative embodiment, a constant-pressure, volumetric measurementsystem can be used in conjunction with the acoustic system to quantifythe flow across a valve that is not closed and to verify that the flowrate is zero when the valve is believed to be closed. If the measuredflow is due to an incompletely closed valve, then this flow will bedecreased or eliminated as the valve is more completely closed. Becausea constant-pressure volumetric system can detect smaller flows than anacoustic system, the use of the volumetric system with the acousticsystem further reduces the number of false alarms due to incompletelyclosed valves over that of an acoustic system. The constant-pressure,volumetric system will also detect any residual flow not associated withan incompletely sealed valve, and as an alternative embodiment, aconstant-pressure volumetric testing system can be used instead of apressure testing system for testing a portion or all of the BOP systemfor leaks. In this test, the pressure is maintained at the test pressureand the volume changes, which would result in a pressure drop, aremeasured directly and can be converted to an equivalent pressure drop,if necessary. While a constant-pressure volumetric testing system iscommonly for petroleum pipelines at airport and petroleum fuel storagefacilities, it has not been used for testing the BOP system. The mainadvantage of the volumetric test as compared to a pressure test is thata direct measurement of the flow across an incompletely sealed valve canbe made in gallons or gallons per hour and it can be used in conjunctionwith the acoustic system to verify that the valves are completelyclosed. As illustrated in FIG. 18, a constant-pressure volumetrictesting system implemented for short runs of piping was used to verifythat there was flow or no flow across the valve for the laboratory testconfiguration and for quantifying the flow rate across the valve if itwas not completed sealed.

As illustrated for a simple pipe and valve configuration in FIG. 2, thepreferred embodiment of the valve measurement system is comprised of twoacoustic sensors mounted on the outside of the pipe with one sensor oneither side of the valve. As an alternative embodiment, the valvemeasurement system can be implemented with only one acoustic sensorpositioned close enough to a valve that is not completely closed todetect any flow noise produced by that valve, but if flow noise from avalve is detected, it is not possible to say with certainty that it isthe valve closest to the acoustic sensor that is not completely closed.With two or more acoustic sensors, where at least one acoustic sensor islocated on either side of the valve, a definitive statement about thestatus of the valve that is bracketed by the acoustic sensors can bemade, because the source of the valve flow signal can be “located”between the two sensors. An accurate location estimate indicates thatthe bracketed valve is producing the valve flow signal. Once thisbracketed valve is closed, another acoustic test will determine if othervalves may also be incompletely closed. As another alternativeembodiment, a third or fourth acoustic sensor can be mounted on thepiping leading into the valve but at a known separation distance fromeach sensor bracketing the valve. The two acoustic sensors on each sideof the valve (not bracketing the valve) can be used to compute thevelocity of the flow noise propagating through the piping, which leadsto more accurate location of the valve between the two acoustic sensorsbracketing the valve. They can also be used to determine from whichdirection a valve flow signal is coming from. To either locate the flownoise source or to compute the propagation velocity requires that thedistance between the acoustic sensors be known. The most reliableverification that a valve with bracketing acoustic sensors is completelysealed requires that the distance between two acoustic sensorsbracketing the valve and from each sensor to the valve be known.However, such verification can also be accurately performed withoutknowing these distances.

The preferred embodiment of the present method and apparatus of thevalve measurement system is comprised of two acoustic sensors mounted onthe outside of the pipe with one sensor on either side of the valve. Theacoustic sensors can be permanently mounted on the pipe wall or thevalve itself, or temporarily mounted on the pipe wall or the valveitself with epoxy, straps, or magnets. The presence of a small flowacross the valve can be detected by comparing the ratio of the crossspectra obtained (1) with a pressure difference across the valve and (2)with no pressure difference across the valve, which preferably isobtained when the pressure on both sides of the valve is 0 psig. Thisapproach works because cross spectral analysis allows one to determinethe relationship between two time series as a function of frequency, andif there is, to determine what the frequency characteristics orfrequency band where the relationship exists. The ratio automaticallyeliminates the background noise in the non-valve-signal frequency bandsand computes the excess signal in the valve-flow-signal bands. Thisapproach works even if the background noise is found in the valve-signalband provided that the background noise is stationary over time, i.e.,is approximately the same in a statistical sense during the valve testas when the background noise was obtained. If not, an adaptive noisecancellation method using the acoustic data from a separate acousticsensor that only measures background noise during the valve measurementtest to remove the background noise from the acoustic sensors during thevalve test. Once the background noise is removed from the time series ofthe two acoustic sensors bracketing the valve, the ratio of the crossspectra obtained with and without a pressure difference works asindicated in the preferred embodiment. In an alternative embodiment, thecoherence function can also be computed between the two acoustic sensorsand used to determine if there is flow across the valve or if thebracketed valve is the incompletely sealed valve generating the valveflow signal. A background coherence measurement can help determine ifthere is ambient noise at frequencies not usually observed.

This can be implemented when there is a pressure difference if the noisecancelled times series from both sensors is used to compute thecoherence function, or if the frequency band containing the valve flowsignal can be identified or is known from previous measurements. Thevalve flow signal can be identified against random background noise ifthe phase of the coherence function is highly linear and themagnitude-squared of the coherence function is strong, as describedbelow. This approach has been used for locating leaks in pipes. Thecoherence function obtained when there is no pressure difference willhelp identify the background noise in the coherence function obtainedwhen there is a pressure difference across the valve.

With two or more acoustic sensors, where at least one acoustic sensor islocated on either side of the valve, a definitive statement about thestatus of the valve that is bracketed by the acoustic sensors can bemade, because the source of the valve flow signal can be located betweenthe two sensors, if the source of the valve flow signal is from thebracketed valve. The valve flow signal can be located using the phase ofthe coherence function of the valve test at frequencies where γ² is highand the phase is linear, which is the approach used for locating pipeleaks. An accurate location estimate of the valve between the twoacoustic sensors indicates that the located valve is producing the valveflow signal and needs to be closed. If a third or fourth acoustic sensoris mounted at the other end of the piping leading into the valve and ata known separation distance from each sensor bracketing the valve, thenany leaks in the piping or the pipe flanges can be located using asimilar approach. A strong response in the magnitude squared of thecoherence function (where γ² is high) and/or the presence of a linearrelationship (where ϕ is linear) can be used independently of thelocation method to determine the presence of a valve flow signal,because γ² is the normalized cross power spectrum.

As indicated above, another alternative embodiment is the use of a thirdand/or fourth acoustic sensor are mounted on the piping leading into thevalve and at a known separation distance from each sensor bracketing thevalve. Any combination of two sensors bracketing the valve can be usedto locate the source of the flow noise at the valve, even if thesesensors are not equally spaced around the valve or in the immediateproximity of the valve. The method can work with a spacing of 500 ft ormore, but for best results the maximum spacing should be less than 50 to100 ft. The two acoustic sensors on each side of the valve (notbracketing the valve) can be used to compute the velocity of the flownoise propagating through the piping. To either locate the flow noisesource or to compute the propagation velocity requires that the distancebetween the acoustic sensors be known.

The acoustic method works, because a valve that is partially closed willproduce flow noise that is cause by liquid flow across the valve. Thestrength of the flow noise will increase as the pressure increases. Thepressure wave produced by the flow through the hole or slit that remainsafter a valve is thought to be fully closed propagates down the pipe.Three primary propagation modes are possible in the pipe leading to anacoustic sensor: (1) through the liquid, (2) at the interface of theliquid and the inner pipe wall, and (3) in the pipe wall. The strongestpropagation mode is through the liquid. All three propagation modes canbe present at the same time and can be present in a wide range ofdifferent frequencies, including overlapping frequencies. Regardless ofthe propagation mode, this flow noise will be strongest in one or morefrequency bands that are controlled by the materials, liquid media, andthe type and configuration of the valve and piping system. Our crosspower spectral and/or or coherence/correlation signal processingapproach does not require a priori knowledge of the propagation modes orpropagation frequencies.

As stated above, the presence of valve flow noise, which is the acoustic“signal” to be detected by the valve measurement system, is determinedby comparing the acoustic times series collected with one or moreacoustic sensors (a) without the presence of a valve flow signal to theacoustic times series collected with these same acoustic sensors (b)with the presence of a valve flow signal. If the background noise islarge or contaminates the valve flow signal, then noise cancellation maybe required.

The valve flow signal can be eliminated by collecting time series dataon the two acoustic sensors bracketing the valve when the pressures arethe same on each side of the valve. This pressure condition can beassured by opening the valve or by lowering the pressure in the pipingon both sides of the valve to 0 psig, which is a special case of theaforementioned. Also, when the pressure is 0 psig, no valve flow noisecan be created. This is true even if the valve is partially closed. Whenthe pressures are the same, no flow across the valve is possible andtherefore, the valve flow noise due to a valve which is not totallysealed will not be produced.

There are a variety of different types of background noise that mightimpact the valve measurements. Background noise emanating from a singlelocation or a single source can be mistaken for the valve flow signal. Agenerator or a pump would be examples. These sources of noise can bevery large and much larger than the valve flow signal itself.Fortunately, these sources of noise are generally found in one or morenarrow frequency bands that are generally not the same frequency bandsas the valve flow signal and can be removed by filtering or by analysesthat does not include these bands in the processing once the noise andsignal bands are known. The method for computing these frequency bandsis described below. If the single location or single source noise isfound in the valve flow signal frequency bands, then one or more noisecancellation methods can be used before the method mentioned above isperformed. If these noise sources do not seriously contaminate the valvesignal band, it will not be necessary to use noise cancellation.

Another type of background noise is broadband noise that occurs at allfrequency bands, including the valve flow signal bands. If this level ofnoise is larger than the valve flow signal, it can mask the valve flowsignal and must be reduced before the analysis method is applied throughadvanced signal processing. Averaging can be used (1) to reduce thebackground noise by the square root of the number of samples averagedtogether and (2) to increase the valve flow signal in proportion to thenumber of samples averaged.

The type of analysis method used will depend on whether the backgroundnoise is stationary (i.e., does not change over time). If the noise isstationary, then background noise obtained before, during, or after thevalve flow measurements are made can be used. If the background noisechanges over time, then an adaptive noise cancellation approach will beneeded, so that the measurement background noise will be representativeof the contamination of the valve flow signal at the time of themeasurement. An adaptive approach is needed if the noise is transientand changes over time.

There are many ways to compare the times series collected with andwithout the presence of the valve flow noise signal, but for bestresults the data should be analyzed as a function of frequency. Thepreferred method is to use two acoustic sensors (x and y) bracketing thevalve and to compute the Power Spectra (Gxx and Gyy), the Cross PowerSpectrum (Gxy), the Coherence Functions (both γ² and phase (ϕ), crosscorrelation function after bandpassing the time series data so that onlythe flow noise frequencies are included, and analyze these quantities asa function of frequency. The specific method used will depend on thetype and frequency characteristics of the background noise. It should benoted that the magnitude squared, γ², is the cross power spectrumobtained using two sensors that is normalized by the absolute value ofthe product of individual power spectra. The advantage of the crosspower spectrum for the valve application is that it is quicker tocollect and process the data and the ratio of the cross power spectrumobtained during a valve test and the background cross power spectrumobtained during background tests provides a simple and direct estimateof the signal-to-noise ratio (SNR) to use in detection.

A simple and quick test of each valve in the BOP test configuration isperformed before, during, or after the pressure test using a passiveacoustic valve measurement system (PAVMS). The preferred embodimentattaches two acoustic measurement sensors (denoted herein by x and y orby POS and REF) to the outside wall of the pipe section on each side ofthe valve (i.e., bracketing the valve). The acoustic sensors only needto be within 50 to 100 ft of the valve, but typically 2 to 10 ft fromthe valve. Preferably, the two acoustic sensors should be at differentdistances from the valve (e.g., 2 ft on one side and 5 ft on the other).The preferable method is to time register and to collect a time seriesfrom each acoustic sensor at a sufficient sampling rate and then processthese time series data in the frequency domain in near real-time. Thepresence of a valve flow signal can be determined from either acousticsensor by computing the power spectral density (PSD) of the time seriesand looking for peaks or excess power in the spectra as a function offrequency. If the background noise is large or if localized noisesources exist, then this will be difficult to do if one does not know apriori which frequency bands have low noise or what the PSD of thebackground noise is.

The background noise can be determined by collecting data in closeproximity to a valve when the valve is known to be completely sealed, orwhen the pressure on both sides of the valve are the same or at zerogauge pressure, which means there can be no valve flow noise. Inaddition, an acoustic sensor may be located in close proximity to thevalve but not on the valve or piping that would be subject to the valveflow signal, if it were present. In all four cases, the time series andPSD are only a function of the background noise, and such backgroundnoise may include general background noise, system/instrumentationnoise, and localize sources of noise (e.g., a generator). If a valve isnot completed sealed and there is a pressure difference across thevalve, then the time series and the PSD contain this signal, as well asthe background noise. If an independent measurement of the backgroundnoise is made, as suggested above, then there will be a difference inthe two time series and the two PSDs.

There are a variety of methods to determine if there is a difference.One is to visually inspect the time series and/or the PSDs and tocompare the differences analyzed as a function of frequency or frequencybands. A second approach is to remove the background noise from thevalve flow signal data by noise cancellation. If the time series of thebackground noise is obtained at the same time as the valve flow signaltime series (and time registered), then one of many adaptive noisecancellation algorithms can be used. If the background noise is obtainedat a different time than the valve flow signal time series (e.g., beforeor after the valve flow signal measurements are made), then an averagetransfer function can be obtained and used for noise cancellation. Thislatter approach assumes (i.e., requires) that the background noise isstationary (i.e., does not change over time). A third approach is tocompute the ratio or difference of the valve flow signal data with thebackground noise data.

All three methods will work, but our preferred method uses the ratio ofthe cross PSDs (valve flow test and background noise test) if twoacoustic sensors are used, especially if they bracket the valve. If onlyone acoustic sensor is available, then the ratio of the PSDs (valve flowtest and background noise test) can be used. This preferred methodallows a direct comparison and easy visual interpretation of thedifferences between the valve flow signal and the background noise as afunction of frequency or in frequency bands so that the frequency bandswith the strongest signal and/or the smallest background noise can beanalyzed and used to determine whether or not a valve is closed. Theequivalent analysis can be performed on the time series, but thisusually requires some a priori knowledge of the background noise to besuccessful and typically usually requires frequency domain analysisusing PSDs to develop the most efficient analysis method. Noisecancellation can be effective in removing background noise from thevalve flow signal, which also contains the same background noise. Takingthe ratio of the power spectra of the valve flow signal (with backgroundnoise) and the background noise, as indicated above, is a simple butdirect form of noise cancellation. The disadvantage of this approach isthat the background noise is usually obtained at a different point intime and may not be the same as when the valve flow signal test data isobtained. This is minimized if the data collection time is sufficient toprovide a reliable estimate of the average background noise that wouldbe representative of the background noise at any time. Adaptive noisecancellation addresses this problem, because the background noise ismeasured at the same time as the valve flow signal.

Adaptive noise cancellation requires that an independent measurement ofthe background noise be made that does not contain the valve flowsignal. A separate acoustic sensor, which is not attached to the pipe orvalve, but is located in close proximity to the valve flow signalacoustic sensor, is used to measure the background noise. This approachmay not measure those acoustic vibrations that can only be sensed byattachment to the pipe or valve when the valve is completely closed orthe pressure difference across the valve is zero. Providing that theaverage background noise during the BOP test is stationary (i.e.,approximately constant), which is not an unreasonable assumption forthese measurements, then a measurement of the background noise with thevalve flow signal acoustic sensor with the valve completely closed, azero gauge pressure on both sides of the valve, with equal pressure onboth sides of the valve, or with the valve open, should provide thenecessary background data to use in effectively detecting the valve flowsignal.

Because the BOP piping configured for a pressure test may include amultiplicity of valves and because the distances between valves aregenerally not large enough to prevent the detection of a valve flowsignal from other nearby valves that are not totally closed, an acousticsensor may detect the presence of a valve flow signal that is notimmediately adjacent to the sensor. In this case, the acoustic test willindicate that a valve is not sealed, but it may not be useful inidentifying which valve is not closed. This problem is addressed usingtwo acoustic sensors that bracket the valve, because these two acousticsensors can be used to locate the source of the valve flow signal usingthe coherence and cross correlation methods. If the valve between thetwo acoustic sensors is not closed and the location of the source of thevalve flow signal is the location of the valve, then this locationmethod indicates that that valve is not closed. If the valve beingbracketed by the two acoustic sensors is closed, then these two acousticsensors will not locate it, but will indicate which direction (i.e.,which side of the valve receives the valve flow signal first) the valveflow signal and the next valve to check. When two acoustic sensors donot bracket the valve flow signal, they can be used to estimate thepropagation speed of the acoustic valve flow signal as a function offrequency and used for more accurate location estimates. The propagationspeed can vary depending on the propagation mode. In general, threeacoustic sensors are best used to locate the valve flow signal, whereone pair brackets the valve and the other pair does not. The pair thatdoes not bracket the valve, as indicated above, is used for estimatingthe propagation speed as a function of frequency, and used to convertthe time of arrival measurements for the two acoustic sensors bracketingthe valve to distance and location relative to the acoustic sensors.

The coherence function or the cross correlation function afterappropriately processing the time series in a signal band is used tolocate the leak. The location estimate is determined as a function ofthe derivative of the phase (di) as a function of frequency in frequencybands where the phase is approximately linear and the when themagnitude-squared (γ²) is higher than the background. This method hasbeen used to locate leaks in buried piping and is equally applicable fordetecting and locating the source of noise produced by an incompletelyclosed valve. If the background noise is large or is found in certainfrequency bands where the valve flow signal also is found, then the timeseries of the acoustic sensors used for location should be noisecancelled before the coherence function is computed. If the backgroundnoise occurs in different frequency bands than the valve flow signal,then noise cancellation is not required if the valve flow signal bandscan be identified. These frequency bands can be identified by comparingthe valve flow coherence function, or the cross spectra and powerspectra used to compute the valve flow coherence function, to thebackground coherence function, or the cross spectra and power spectraused to compute the background coherence function. As mentioned above,the background noise can be measured with the valve flow signal acousticsensor when the valve is completely closed, with a zero gauge pressureon both sides of the valve, with equal pressure on both sides of thevalve, or with the valve open.

The cross correlation function can also be used to locate the valve flownoise and the propagation speed using the same acoustic sensors that areused when computing these quantities using the coherence function.However, without knowing a priori the frequencies where the valve flowsignal is strongest relative to the background noise, these estimatesmay be too contaminated with background noise to be accurate. If thecross correlation function is processed in the same frequency bands asused by the coherence function, the results will be similar. Theadvantage of the coherence function approach is that no a prioriknowledge of the frequency content of the valve flow signal or thebackground noise is required, because it is derived as part of thecomputation. This is also true of the cross power spectrum and the ratioof the cross power spectra and the ratio of the individual acousticsensor power spectra obtained during the valve test and during thebackground measurements.

The coherence function is comprised of the magnitude-squared (γ²) andthe phase (ϕ). γ²) is computed from the magnitude squared of the crossspectrum of the time series obtained from the two acoustic sensorsbracketing the valve of interest divided by the magnitude square of thepower spectra obtained for each acoustic sensor. Because both γ² and ϕare computed as a function of frequency, the frequency bands computingthe valve flow signal and the background noise can be assessed as partof the computation. The signal-to-noise ratio (SNR) as a function offrequency (SNR (f)) is computed directly from γ² (i.e., (1−γ²)/γ²). TheSNR(f) as a function of frequency can also be computed from the crossspectrum obtained with a valve flow signal present and without a valveflow signal present (i.e., background noise).

Our preferred analysis method is to compute the ratio of the cross powerspectrum obtained during a valve flow signal measurement and the crosspower spectrum obtained when the pressure difference across the valve isequal or the pressures on both sides of the valve are zero and to set athreshold that is statistically different than 1 at a high enoughconfidence level to meet the required performance standard. Typically,this can be expressed as a minimum SNR or in terms of a probability ofdetection (P_(D)) and a probability of false alarm (P_(FA)). ForGaussian background noise, SNR is easily related to (P_(D)) and(P_(FA)). In general, the regulatory agencies require testing to beperformed with a system capable of achieving a P_(D)≥95% against theflow rate of interest and a P_(FA)≤5%. Most systems need to operate witha P_(FA)≤1%.

There are many ways to establish a threshold that results in anacceptably high P_(D) and an acceptably low P_(FA). One way is to select(i.e. compute) a threshold based on the P_(D) against the minimum levelof valve flow that is acceptable in a BOP pressure test and the P_(FA)that does not require many retests to insure the valve is tight. Anotherway is to do a hypothesis test with acceptable Type I and Type II errorsto differentiate the signal plus background noise from the backgroundnoise for the PSD or Cross PSD or their differences. Another way is todo a hypothesis test with acceptable Type I and Type II errors todifferentiate the ratio of the signal plus background noise from thebackground noise for the PSD or Cross PSD. This is really evaluating theSNR. This can also be done for the coherence function. This can beenhanced by taking into account those frequency bands where the phase islinear. The ratios or SNRs, when converted to dB, can also be used toset a threshold. Thresholds of SNR can be related to P_(D) and P_(FA) todetermine the SNR threshold. Typical numbers for P_(D)≥95 to 99% andP_(FA)≤1 to 5% for small valve flows that would not trigger a pressuredrop threshold exceedance during a BOP pressure test. The Type I andType II errors are the same as 1−P_(D) and the P_(FA), respectively. SNRthresholds can be as low as 10 dB and may be as high a 15 to 20 dBdepending on the required performance.

The background time series is usually obtained before testing eachvalve. If the ratio of the cross power spectra indicates the presence ofthe valve flow signal, then these two sensors should be used to locatethe source to verify that the valve between the two acoustic sensors isthe source of the valve flow signal. A volumetric system can be used todetermine the magnitude of flow and when the valve is sufficientlyclosed to perform the pressure test. The propagation speed can bemeasured using two acoustic sensors not bracketing the valve or byscratching the external side of the pipe when the valve is open, whenthe pressure is the same on both sides of the valve, when the pressureis zero on both sides of the valve, or when the valve is known to beentirely closed. Lightly scratching the surface of the pipe with a smallscrew driver or knife produces a signal equivalent to a small valveflow.

The time series used to compute the PSDs, the cross PSD, or thecoherence function can be analyzed with equivalent results to determinethe presence of a valve flow signal if the frequency bands where thevalve flow signal is large and/or the background noise is small. Asindicated above, this is also true for the cross correlation function.The mean, median, standard deviation, variance, or power can be computedusing the time series. If the time series are bandpassed to thosefrequency bands where the valve flow signal is large and/or thebackground noise is small, the presence of the valve flow signal can bedetermined. If the time series of the valve flow signal is noisecancelled, then the determination is not impacted by background noise.In general, it is more efficient to analyze these data in the frequencydomain.

For best results the background noise should be obtained with the samesensors and electronic systems that are used to measure the valve flowsignal. Thus, it is preferable to estimate the background noise fromthese acoustic sensors when the valve flow signal is not present (i.e.,typically when the pressure on both sides of the valve are equal orpreferably zero). This will work providing the background noise isstationary during the valve measurements. If not, then an adaptive noisecancellation method needs to be applied using data from an independentacoustic sensor not subject to the valve flow signal during the acousticvalve measurements.

If two acoustic sensors are located on the same side of the valve, thenthe propagation speed of the valve flow signal can be determined andused in more accurately locating the valve flow signal. The acousticdata is collected at 100 kHz (up to 200 kHz) and the basic approachtaken for detecting and locating leaks in pipelines is applied tovalves. This approach is described below. The preferred method is tocollect data with two acoustic sensors bracketing each valve before theline is pressured (i.e., at a pressure of 0 psig) with the valve open tothe piping on both side of the valve. A sufficient set of times seriesshould be collected to develop a transfer function under the backgroundnoise conditions for noise cancellation. Once this background noise datais obtained, the BOP system should be pressurized for the conduct of thepressure or volumetric test. If one or more of the valves is not sealed,then flow noise will occur and can be detected from the coherence, crossspectra, or correlation (after appropriate bandpassing to the flow noisesignal band(s) using the noise cancelled time series. The coherencebetween the two sensors is computed and the frequency band containingthe valve flow signal is determined by looking for a highmagnitude-squared and/or a linear phase relationship.

The number of sensors can be minimized and optimized by having thesensors bracket multiple valves. The acoustic sensors do not need to bein close proximity to the valve and distances up to 100 ft or more wouldalso accommodate the acoustic measurements needed to determine whetheror not a valve is closed. This two-sensor configuration increases theperformance and allows the acoustic sensors to detect small flows acrossthe valve because of Vista's signal processing algorithm, which removesthe noise not specifically present in the flow signal frequency band.

The main advantage of the acoustic valve flow measurements is that thenumber of pressure tests necessary to indicate the BOP system integrityis minimized, and may allow for the entire BOP system to be tested inone or two tests. More than one pressure test may be required if two ormore valves are used on each side of the valve for redundancy. If all ofthe valves seals can be verified, then it should be possible to test theentire as a single configuration (vice the 9 configurations currentlyrequired.) To check all of the valves, we would use a modified versionof our constant-pressure, dual pressure, volumetric leak detectionsystem (HT-100 Volumetric Leak Detection System) to maintain a specifiedlevel of pressure during the acoustic measurements and to measure theflow across the valves at this pressure in real-time until all valvesare completely sealed as determined by the PALS Leak Location Systemmodified and used as Valve Testing System.

Possible Locations of Acoustic Sensors. FIGS. 3 through 10 illustrateeight of many different acoustic sensor locations that can be used todetect the presence of an incompletely closed valve by detection of thevalve flow signal produced by flow across the valve. FIGS. 7 through 10illustrate four acoustic sensor location that can be used to locate thesource of the valve flow signal, which location can be used to determinewhether or not the valve being examined is the source of the valve flowsignal (i.e., whether or not it is closed). FIG. 6 can be used todetermine which direction the valve flow signal is coming from, andtherefore, which valves (the one on the left or the two on the right)may be the valve that is not closed.

FIGS. 3 and 5 illustrate the use of a single acoustic sensor. FIG. 3illustrates that acoustic measurements can be made at pressure to detectthe presence of a valve flow signal. FIG. 5 illustrates that acousticmeasurements can be made prior to or after these valve flow measurementsto estimate the average background noise. As stated above, this can beaccomplished by making acoustic measurements when the valve is known tobe tight or when the pressure is the same or zero on both sides of thevalve. Both analyses of the raw or noise cancelled acoustic sensor timeseries or the power spectrum can be used to detect whether or not valvebeing tested is sealed. The preferred method of analysis is the take theratio of the power spectra obtained when there is a pressure differenceacross the valve and when there is no pressure difference across thevalve.

FIG. 4 illustrates the configuration in FIG. 3, but includes an acousticsensor not located on and not subjected to the valve flow signal, butclose enough to the acoustic sensor on the valve piping to measure thebackground noise. In addition to the analyses methods in FIG. 3, theacoustic sensor not subjected to the valve flow signal can be used as areference for adaptive noise cancellation or average noise cancellation.

FIG. 6 illustrates two acoustic sensors located on one side of the valvebeing examined. In this configuration, the propagation speed of thevalve flow signal can be determined.

Coherence Function and Coherence-based Correlation Methods Used forDetecting and Locating Valve Pipe. The coherence function and thecoherence-based correlation methods developed by the inventor (calledthe Pipeline Advanced Leak-location System or PALS) and used forlocating underground pressurized pipe leaks over distances 300 to 500 ftor more work, well and are well documented. The method works well forunderground or buried pipe because the background noise is minimizedsimply because the surrounding backfill and soil dampens any ambientacoustic background noise. This approach does not work, or work well,however, for locating leaks in aboveground piping, because of the largeamount of ambient background noise. The aboveground piping acts as an“acoustic antenna” for background noise, which interferes with theability of the pipeline leak location system to work. Similarperformance issues arise for valves, because they are locatedaboveground. As a consequence, these location methods have not beenapplied to piping valves located aboveground.

The author developed a method for applying these location methods toaboveground valves both for detection and for location. The methodrequires that background measurements be made when it is known that thevalve is completely closed, or the pressure is the same on both sides ofthe valve (i.e., 0 psig). The background measurements can be used toidentify those frequency bands where the noise is strong and should beavoided in the detection and location algorithms. This approach onlyneeds to be used if there is some indication that the valve flow noisedetected with the preferred method may not be the valve being tested.Also, accurate location of the valve is not required provided thelocation (and the valve) is between the two acoustic sensors.

Overview of Coherence Function and Coherence-based Correlation MethodsUsed for Locating Leaks in Underground Pressurized Piping. As describedbelow, PALS was originally developed for locating holes in undergroundpipelines containing refined petroleum fuels and ranging in size from 2in. to over 30 in. in diameter. PALS uses three sensors spaced atintervals along the line (see FIGS. 9 and 11). Two of the acousticsensors bracket the valve and two of the sensors are on the same side ofthe valve. The two sensors bracketing the valve are used to locate theleak and will also be used to locate the source of the valve flow signal(i.e., the valve) and the two sensors on the same side of the valve areused to determine the propagation speed as a function of frequency touse in converting the acoustic time data to distance data for thelocation estimate. An in-house laboratory study was performed todetermine whether or not PALS could detect and locate small leaks, leaksas small as 0.2-gal/h leak, which is EPA's regulatory performancestandard for detection of leaks in underground pipelines found as gasstations, and if it could, how far could the sensors be separated andstill achieve acceptable performance. The ability to detect and locatesmall valve flows was demonstrated as part of an in-house, internalresearch and development project where the measurements made to detectand locate leaks smaller than 0.2 gal/h. The measurements made in thelaboratory using a small valve in a short section of pipe to simulatethe leak in the pipe (see FIG. 18) apply directly. The valve flow wasdetected from the ratio of the PSD obtained during the tests when thevalve was cracked and the PSD when the pressure was zero or the same onboth sides of the valve.

PALS achieves a high level of performance because of a unique approachto signal processing based on coherence analysis that enables the leaksignal to be identified as a function of frequency so that frequencieswith high background noise could be avoided. The basic signal processingmethodology used by the PALS was first demonstrated in 1991 on anunderground 200-ft, 2-in.-diameter underground fuel pipeline. Furthertests—on a 100-ft, 6-in.-diameter pipe section installed at the TestApparatus—were conducted in 1995 immediately prior to the start of thefurther testing. In 2000, the author demonstrated the performance of thePALS for the DoD at four different underground pipelines located in NewJersey, Arkansas, Kentucky, and California. Tests were conducted on the1015-ft-long, 12-in.-diameter Navy Test Loop that was part of the SERDPTest Pipeline Facility (STPF). The PALS's performance was consistent inall of these tests: for line segments less than 200 ft long, the systemlocated leaks within 3 ft or less of their actual positions; for linesegments longer than 200 ft, the system located leaks to within 1.5% ofthe distance between sensors. In most of the tests, leaks were “created”through the use of removable leak plugs, with diameters of 0.01 and 0.04in.

A description of the PALS method is provided below. It includes thealgorithms based on the coherence function, as well as some examples oftest results from the STPF. This description is followed by adescription of the valve tests for very small flows and for flows andsome background conditions found on a BOP.

System Description. A brief description of the PALS is presented below.As illustrates FIG. 11, the PALS is comprised of three small acousticsensors, three small pre-amplifiers, and a field-worthy notebookcomputer having a data acquisition card. There are a wide number ofacoustic sensors or accelerometers that could be used. We have usedacoustic sensors from Endevco, Physical Acoustics, Hartford SteamBoiler, and many others with good success. The cables connecting thepre-amps to the data acquisition card in the computer can be up to athousand feet in length. The cables connecting the pre-amps to thesensors generally have length restrictions of 10 ft to 100 ft, or so.Communication between the sensor-pre-amp subsystem and the computercould also be accomplished by wireless communication.

The sensors can be attached directly to the pipe wall, flanges, or thevalve with epoxy, a magnet, or a strapping system for portable testingand easy removal or permanently mounted on the pipe wall, flanges, orvalve.

Each sensor measures the acoustic signal generated by the flow through ahole in the pipe. A pair of sensors called the “position” (POS) and“reference” (REF) sensors bracket the leak and determine the location ofthe leak relative to the Reference sensor. A second pair of sensors,which do not bracket the leak, is used to measure the speed ofpropagation of the acoustic signal in the pipe. The propagation speed ismeasured with the “velocity” (VEL) and the reference sensors. For theleak to be properly located, the distances between the sensors must beknown—since the measurement made by the PALS determines the locationrelative to the reference sensor for the sensor configuration(VEL-REF-POS). These distances and this sensor configuration must beentered into the PALS software before a measurement can be made. Asecond measurement configuration can also be used, in which both the VELand POS sensors are located to the left or right of the REF sensor(REF-VEL-POS). The REF-POS sensors still bracket the leak, but theREF-VEL sensors do not. A leak-location measurement can take as littleas 10 s to 1 min and sometime 2 to 5 minutes to complete. (For valvetesting, the measurement takes less than 5 s for detect and less than 1min if a location measurement is required. Both configurations were usedin the pipeline tests illustrating the capability herein.

The PALS uses automatic gain control and has a 16-bit data acquisitioncapability. The data acquisition card allows data to be collected at amaximum sample rate of 200,000 samples/second (200 kHz) and can processup to 200 ensembles per second comprised of up to 16,384 samples perensemble. The Nyquist sample rate is 100 kHz, which is sufficient toexploit the leak signal over the frequency band of interest. The samplerate and ensemble length, which control the maximum separation distanceallowed for the position and reference sensor pair, can be selected soas to maximize the number of ensembles averaged together in the shortesttime. The software prints out the maximum separation distance possiblefor the choice of sample rate and ensemble size and warns the user ifthe parameter selection is not sufficient.

Coherence-based Detection Algorithm. PALS uses a coherence functionsignal-processing algorithm to locate a leak. The coherence approachovercomes the difficulties experienced with amplitude and correlationanalyses. PALS uses the coherence function to determine the existence ofan acoustic signal and to determine the frequency band that contains thesignal. The existence of the signal and the frequency band containingthe signal are determined from both the magnitude-squared (γ²) and thephase (ϕ) displays. Once the frequency band containing the signal isselected, the location of the leak relative to the reference sensor canbe estimated from the phase data. The PALS software implements thisalgorithm.

The γ² display allows for the frequency band with the strongest leaksignal to be identified, and the ϕ display allows for an estimate of thelocation of the leak to be made. The γ² display is not sufficient byitself to identify which frequency band to use in the analysis. Thephase of the frequency band selected for the analysis must be linear andstable, qualities that may be present in only a portion of the frequencyband identified by γ². There may be multiple frequency bands thatcontain the signal, or one or more of these signal bands may becontaminated by different propagation modes or multipath reflections.The propagation velocity to use for each frequency band is notnecessarily known a priori. In some cases a theoretical estimate of thepropagation velocity can be used, but to ensure accurate locationestimates it needs to be measured in most cases.

Unlike the correlation function, the coherence function determines therelationship between two time series as a function of frequency. Thismeans that the coherence function can be used for leak locationindependently and without a priori knowledge about the properties of thepipeline or the leak; this is not possible using the correlationfunction.

Once the coherence function has identified the leak signal frequencyband, the correlation function can be used to verify that only one leaksignal exists and that reflections from other sections of the pipelinedo not interfere with the location estimate. Multiple reflections orleak signals show up as multiple peaks in the correlation function.Small changes in the frequency band used to perform the leak locationanalysis often eliminate one or more of the multiple peaks, if they arepresent, and allow for a reliable estimate of location to be made. Thisuse of the correlation function is powerful, but it works only becausethe signal band has already been determined from the coherence function.

Eqs. (1) and (2) can be used to compute the position of the leak and thepropagation speed of the leak signal in the pipe, respectively, usingthe output of the coherence function. The location of the leak withrespect to the REF sensor can be computed from the output of the phasedisplay for the POS-REF by

X _(REF-Leak) =X _(REF-POS)/2−(Vd _(ϕREF-POS) /df)/(4π)  (1)

where X_(REF-Leak) is the distance from the reference sensor to theleak, V is the propagation velocity to use in the calculation, and dϕ/dfis the slope of the linear portion of the phase plot in the frequencyband containing the leak signal.

The propagation velocity, V, can be computed from the output of thephase display for the VEL-REF by

V=2πX _(REF-VEL)(d _(ϕREF-VEL) /df))⁻¹  (2)

Illustration of PALS at the STPF Underground Test Pipeline. An exampleof the output of the coherence function (γ², ϕ) for the three sensorspositioned on the test pipeline is illustrated schematically in FIG. 13.The sensors are labeled REF2, VEL, and POS. A leak of 1.9 gal/h flowsthrough a 0.01-in.-diameter hole into a saturated sand backfill. Alltests were conducted with water in the test pipeline and at a linepressure of 70 psi. The underground test pipeline is a 12-in.-diameter,schedule 40 pipeline that is buried approximately 3 ft in a sandbackfill. A schematic of the line is shown in FIG. 12. The line, whichis 1,015 ft long, begins at a vertical riser that extends about 3 ftabove the ground and terminates with a blind flange at another 3-ftvertical riser. The pipeline is U-shaped with two long runs of 500 ftand a short section of 15 ft. The leak was located 233.5 ft from theoutlet riser. Sensors can be mounted on 17 carefully measured specialaccess points, and on the exposed pipe at the two vertical riserslocated at the ends of the pipe and in an open concrete test pit. Inaddition, the line was exposed at three locations where pits had beendug. In these three pits the sensors were attached directly to the lineusing epoxy.

The three pits, which served as the initial positions of the position,reference, and velocity sensors, are denoted POS, REF, and VELrespectively. A constant-pressure, volumetric leak detection system wasattached to the inlet riser to measure the volumetric flow rate of theleak during the acoustic tests and to establish and hold the pressureconstant during the tests.

The distances between the POS-REF and the VEL-REF sensors for the sensorconfiguration shown in FIG. 12 were 360.0 ft and 137.3 ft, respectively.Since the reference sensor is not situated between the velocity andposition sensors, the computed velocity is displayed as a negativenumber. At frequencies above 10 kHz, the leak signal for both thePOS-REF and the VEL-REF coherence functions is clearly seen in FIG. 13.Values of γ² are greater than 0.6 and are clearly greater than thevalues of γ² outside the leak signal frequency band (frequencies lessthan 10 kHz). In this example, the phase ϕ is highly linear, but thephase slope, dϕ/df, changes slightly with frequency in the vicinity ofthe three peaks in γ² found at frequencies of 12.5, 15.5 and 18.0 kHz.The analysis for leak location was performed between 12.6 and 14.0 kHz.The results are summarized in Table 1.

TABLE 1 Leak Rate of 1.9 gal/h for a 0.01-in.-diameter Hole in the TestPipeline PALS Test Results 0.01-in. hole, Measurement 1.9 gal/hConfiguration (see Figure) FIG. 12 Reference - Position SensorSeparation 360.0 ft Distance -ft Reference - Velocity Sensor Separation137.3 ft Distance - ft Velocity - m/s 1,409 m/s PALS: Reference -Leak-Location Distance - ft 233.1 ft Actual: Reference - Leak-LocationDistance - ft 233.5 ft PALS: Error: Reference - Leak-Location 0.4 ftDistance - ft PALS: Reference - Leak-Location 0.1% Distance - % ofREF-POS Distance

In this example, the PALS located the leak to within 0.4 ft (or 0.1% ofthe 360.0-ft POS-REF separation distance). The PALS indicated that theleak was 233.1 ft from the REF sensor, and the actual location of theleak was 233.5 ft. A measured propagation velocity of 1,409 m/s was usedin the analysis.

FIG. 13 also shows the output of the correlation function on the bottomright corner for this frequency band (12.6 to 14.0 kHz). The correlationfunction shows a single, highly defined peak with a time delay of 30 ms.For a propagation velocity of 1,409 m/s, the position estimated with thecorrelation function is 236 ft, which is nearly identical to theestimate made with the coherence function. For this type of example,where the leak signal is very strong and the phase is very linear, thecoherence and correlation functions should, as they did, give nearlyidentical results.

FIG. 14 shows the output of a leak-location test conducted in theabsence of a leak. The γ² display is approximately zero over the entirefrequency range, and the ϕ display exhibits a random, irregular, andnonlinear behavior. The correlation function does not show anywell-defined peaks. FIG. 14 illustrates the output when the ambientbackground noise is negligible.

FIG. 15 illustrates the most typical acoustic sensor configuration(VEL-REF-POS). This configuration was intended to test the PALS over adistance of 159.5 ft on a straight section of pipeline away from theends. The output of the coherence function is shown in FIG. 19. The leakwas located to within 0.5 ft of the actual location. The positionmeasured with the PALS was 33.5 ft, and the actual position was 33.0 ft.The estimate of the leak position used the measured velocity of 1,621m/s and the analysis was based on the frequency band between 17.6 and18.4 kHz.

The accuracy of the PALS determined from the results of 19 tests issummarized in Table 2 is approximately 1% of the separation distancebetween the reference and position sensors bracketing the leak. Theaverage error for these tests is about 3 ft over distances that rangedfrom 159.5 to 516.5 ft. In general, the accuracy of the test resultsranged between 0.5% and 2.5% of the spacing between the reference andposition sensors. The location accuracy was not strongly correlated withsensor separation distance. This result makes sense, because only thosetests with adequate signal-to-noise ratio were analyzed.

TABLE 2 Summary of the Accuracy of 19 Leak-Location Tests Conducted atthe STPF (Sensor Separation Distances between 159.5 and 516.5 ft) PALSLocation Error PALS Location Error (ft) (% of Sensor Separation) Average3.10 1.10 Median 2.65 0.80 Standard Deviation 2.02 0.77

For most valve flow measurements, the flow rates produced by anincompletely sealed valve will be higher than the flow rates used inthese leak location tests and the positioning of the acoustic sensorsrelative to the valve flow/leak will be several feet rather than severalhundred feet. The test pressures for a valve test will also be muchhigher, 250 psig and up to 10,000 psig versus 50 psig to 150 psig. Asdescribed below, the method will work well for both detection andlocation for even very small valve flow rates (0.16 gal/h), which arereally too small to occur for the large valves and high pressures foundon a BOP system.

Valve Measurements. In 2002, the authored performed an internal researchproject to illustrate that leaks smaller than 0.2 gal/h can be detectedand located at distances over 100 ft when the pressure difference was100 psig. The same and other methods of analyses are applied to the BOPvalves, except the background noise is higher and only detection isrequired. Location would only be required if there was some questionabout whether or not the valve being tested was the source of thedetected flow noise. A closed valve was slightly opened to simulate aleak in the pipe or flow across the valve.

FIG. 17 illustrates the test configuration. Our estimate of the valveflow/leak signal was generated by a slightly cracked valve in a25-ft-long, straight section of 2-in.-diameter pipe. Aconstant-pressure, volumetric leak detection and volumetric flowmeasurement system (LT-100) was used to conduct a leak detection test ofa pipe by making volumetric measurements at two constant pressures toremove (i.e., noise cancel) the thermally induced volume changes, wasused to maintain constant pressure in that portion of the pipe on thedownstream side of the valve and to measure flow rate across the valve.Pressure on the upstream side of the valve was maintained by apressurized storage tank half filled with nitrogen. The signal producedby flow across a cracked valve is similar to (but weaker than) thatproduced by a leak through the pipe wall into some type of backfill.

As illustrated in FIG. 17, two acoustic sensors were mounted on thepipe, one on each side of the valve at distances of 8.5 and 3.9 ft(“far” and “near” sensors), respectively, from the valve. The valveitself was located at the center of the pipe. Acoustic data from anumber of 2-min tests were analyzed at a sample rate of 65 kHz for avalve flow rate of 0.16 gal/h.

FIG. 18 illustrates the results of coherence analysis for γ² when thereis no flow across the valve. Some coherent background noise is observedat frequencies below 2.5 kHz—this noise is due to vibrations present inthe laboratory and is not typical of the measurements made on a pipeburied underground. Also, the spikes in the γ² plot in FIG. 18 areanomalous and were eliminated from the PALS. Outside of this coherentband, as seen in FIG. 19, the power spectral density is relativelyflat—representative of the background noise in the system (−36 dBrelative to unity for the “near” sensor and −32 dB for the “far”sensor).

FIG. 20 illustrates the results of the coherence analysis when there isa leak of 0.16 gal/h generated at a line pressure of 52 psi. The valveflow signal is observed in three frequency bands: (1) 2 to 4 kHz, (2)5.5 to 7.5 kHz, and (3) 10 to 32 kHz. The highest frequency band, whichis typically used to locate a leak, is due to propagation of theacoustic leak signal through the liquid. FIG. 21 illustrates the powerspectra obtained for each of the sensors. SNR is estimated from thepower spectra with the 0.16-gal/h valve leak and the background noiselevel estimated from FIG. 18. The PSD of the valve flow/leak data is onaverage 28.75 dB above that of the no-leak data.

Description and Illustration of BOP Valve Flow Measurement Methods. Adescription of methods for detecting, measuring, and locating leaks inunderground piping and flow across valves using a coherence-basedapproach and a bandpassed coherence-based correlation approach wasprovided above. Below we performed specific tests to evaluate ourmethods for detecting incompletely sealed valves in the presence ofgenerator noise. The methods used to generate these results are allapplicable for detection and some may be used for location. The figurecaptions describe and illustrate the method test configuration and thecomputational methods used (FIGS. 24 through 72) for a range ofoperational test conditions.

FIG. 22 illustrates in a photograph the valve flow measurement apparatusassembled to illustrate the capabilities of the valve flow measurementsystem when the piping and valves are located above ground. FIG. 23illustrates one valve flow measurement laboratory test configuration toillustrate the preferred methods of analysis. In this case the VELacoustic sensor is to the left of the REF acoustic sensor and the valveis located between the REF and POS acoustic sensors. FIG. 56 illustratesanother valve flow measurement configuration. In this second case, theVEL acoustic sensor is located between the REF acoustic sensor and thevalve. Both configurations work equally well.

The test results shown in FIGS. 24 through 55 were obtained for the testconfiguration illustrated in FIG. 23. The POS acoustic sensor is 0.375ft (4.5 in.) from the valve and the REF acoustic sensor is located onthe opposite of the valve at a distance of 0.375 ft (4.5 in.) from thevalve. A third acoustic sensor, the VEL sensor is located on the sameside of the valve as the REF sensor and 1.5 ft (18 in.) away from theREF sensor. The REF sensor is 0.75 ft (9 in.) away from the POS sensor.

FIGS. 24 through 39 illustrate the various analyses when the backgroundnoise is relatively quiet (i.e., normal people traffic but no generatornoise). FIGS. 24 through 28 were obtained with the valve partiallyclosed no pressure difference across the valve, i.e., the pressures onboth sides of the valve were 0 psig. This represents a response for aclosed valve. Once we cracked the valve to set the flow rate across thevalve, we did not want to open and close it, because we would not beable to repeat the valve flow tests under the same conditions. FIGS. 29through 34 were obtained with the valve partially closed with a pressuredifference across the valve at the start of the measurements of 100 psigwith the pressure on one side at 100 psig and the pressure on the otherside of the valve of 0 psig. FIG. 31 shows the PSDs of the valve flowrelative to the PSD of the ambient background. FIGS. 35 through 39 usethe results in FIGS. 24 through 34 and compute the SNR by either theratio or the difference in the data produced a valve flow and tightlysealed valve.

FIGS. 40 through 55 illustrate the various analyses when a generator isoperating near the acoustic sensors. While the generator noise isextremely noisy, the presence of a small crack in the valve producing asmall flow is very detectable and can be accurately located. FIGS. 57through 72 were run under similar conditions as the tests results shownin FIGS. 24 through 39 and with similar results.

The plots in each of the figures illustrate the type of analyses thatcan be used to detect the presence of an incompletely sealed valve. Thefigure captions and the figures themselves indicate the method ofprocessing. For each processing run, we show the raw time series, thePSDs, the cross PSD, the coherence function, and the correlationfunction after bandpassing to use the frequency band where the valveflow signal was strongest. We did not process the time series itself,but we could have performed similar analyses, but knowledge of thefrequency bands where the valve flow signal is the strongest and thebackground noise is the smallest needs to be used and best obtained inthe frequency domain. Processing in the frequency domain as a functionof frequency is easier to implement than in the time domain. Thefrequency bands where the valve flow signal is the strongest and thebackground noise is the smallest are determined directly from the peaksin the SNR plots or the coherence analysis.

In general, the detection of a small valve flow is accomplished fromsetting a threshold on the excess power in the SNR plot of the crosspower spectrum of the POS and the REF acoustic sensors, which isproduced by taking the ratio of the cross PSD at the test pressure whenthe valve is cracked and the cross PSD when there is no pressuredifference across the valve, i.e., when both sides of the pipe at 0psig. Alternatively, one can use the SNR of the PSD or either acousticsensor or the average of both. In general, the SNR determined from crossPSD is 5 to 10 dB higher than the SNR of either of the PSDs. Validationthat the valve flow signal being measured is determined by locating thevalve producing the valve flow signal using the magnitude squared andphase of the coherence function or the peak signal in the crosscorrelation function after banding passing as determined from themagnitude squared and/or the phase of the coherence function. Thevelocity measured by the REF and VEL acoustic sensors can be used toaccurately analyze the data when the propagation modes are mixed.

In FIG. 56, the POS acoustic sensor is 1.83 ft (22 in.) from the valve.The REF acoustic sensor is located on the opposite of the valve at adistance of 2.0 ft (24.0 in.) from the valve. A third acoustic sensor,the VEL sensor is located on the same side of the valve as the REFsensor and 0.5 ft (6 in.) away from the REF sensor and 1.5 ft (18 in.from the valve. The REF sensor is 3.33 ft (40 in.) away from the POSsensor. This configuration was used in the analyses illustrated in FIGS.57 through 72 without the generator turned on and is the same series ofanalyses performed in FIGS. 24 through 39.

It should be noted that the acoustic sensors do not need to becalibrated relatively to an absolute standard provided that each sensoris used to record the background noise in the absence of a valve flowsignal and to use in the measurement to determine whether or not a valveflow signal exists. The ratio or SNR of the PSDs or the cross PSDsdivide the relative background noise out. This is also true for thecoherence analyses.

The analyses in FIGS. 24 through 39, FIGS. 40 through 55, and FIGS. 57through 72 start with acoustic time series that have not been noisecancelled. In general, the ratio or SNR computations does the noisecancellation provided that the background noise, such as the generatornoise, does not change between the time the background time series isobtained and the time the valve flow measurements are made. Thisassumption is usually valid, because the valve flow measurements can bemade in a matter of minutes. If this assumption is not true, thenadaptive noise cancellation should be used using an acoustic sensorlocated in a position that it only records background noise and not thevalve flow signal.

FIGS. 24 through 26 illustrate the time series and the PSDs of the POSand the REF acoustic sensors, and the cross PSD of the POS and REFacoustic sensors when the valve is partially closed, but the pressure onboth sides of the valve is 0 psig. Only background noise is observed.The results would be the same if the valve were totally opened, totallyclosed, or at the same pressure on both sides of the valve. FIGS. 27 and28 illustrate the output of the coherence function and the crosscorrelation function for the VEL and REF and the REF and POS acousticsensors. Only background noise is observed.

FIGS. 29 through 32 illustrate the time series and the PSDs of the POSand the REF acoustic sensors, and the cross PSD of the POS and REFacoustic sensors when the valve is partially closed, but the pressure onone side of the valve is at 100 psig and the pressure on the oppositeside of the valve is 0 psig. The presence of the valve flow signal isobserved and is obviously different than the response when the pressureis zero on both sides of the valve. This is clearly illustrated in FIG.31, which plots the PSDs for the background and valve flow signal on thesame plot for the POS and REF sensors. FIGS. 33 and 34 illustrate theoutput of the coherence function and the cross correlation function,where the cross correlation function was bandpassed as determined by thecoherence function, γ². The presence of the valve flow signal isobserved in the magnitude squared (γ²) plot for both sensor pairs and isobviously different than the response when the pressure is zero on bothsides of the valve. The valve was located from the coherencemeasurements. The location of 0.31 ft (from the REF acoustic sensor) isin excellent agreement with the actual location of 0.33 (4 in.).

FIGS. 35 through 37 illustrate the ratio or SNR of the PSDs of the POSand the REF acoustic sensors and the cross PSD of the POS and REFacoustic sensors when the valve flow signal is present and when it isnot, i.e., valve flow signal PSD divided by the background noise PSD.FIGS. 38 and 39 illustrate the difference of the PSDs and the cross PSD.The time series is not a reliable method of detection, because thefrequency contributions are not discernable. If the frequency bandswhere the signal was the strongest and the noise was the smallest wasknown a priori, then the time series could be effectively used. This isalso true if the time series were noise cancelled. The presence of thevalve flow signal might be discernable in the time series, but would bemuch stronger once the right frequency bands were selected. The power inthe time series can be computed from the variance or standard deviationsquared.

The differences in the computed quantities like the PSDs or cross PSDand the ratio or differences of these quantities can be comparedvisually, or statistically. Statistical hypothesis tests can be set upto compare whether or not the ratio is difference from 1 (i.e., no valveflow signal) or statistical differences in the difference quantities atsome level of confidence. These tests can be set up for differenceerrors (in terms of the probability of a missed detections or theprobability of a false alarm). In addition, the SNR can be defined interms of these probabilities.

While not shown, similar detection results can be obtained fromstatistical quantities like the mean, median, standard deviation,variance, and power, which can be computed for the time series, andcompared. Again similar statistic hypothesis tests can be set up for thetime series quantities.

FIGS. 40 through 55 illustrate the response when a generator isoperating in the proximity of the acoustic measurements made in FIGS. 28through 43. In this case, the generator response is found in thefrequency bands below 15,000 Hz (15 kHz). This can be observed bycomparing the PSDs, cross PSD, and the coherence functions withbackground noise only (FIGS. 25 through 26 (or FIGS. 58 through 60) withthe generator background noise illustrated in FIGS. 41 through 43. Thepresence of the valve flow signal is observed, as illustrated in FIGS.52 and 53 (or FIGS. 54 and 55), by the 20 dB excess power observed inthe frequency band above 15,000 Hz. Note that the power in the 0 to15,000 Hz frequency band is similar for the background noise with thegenerator and the valve flow signal with the generator. A separateacoustic sensor could be used to adaptive noise cancel the generatornoise, but this was not necessary for these measurements. The coherencefunction was used to locate the valve. The location measurement shown inFIG. 49 is 0.23 ft. Other frequency bands showed results of 0.31 ft. Alllocation estimates were sufficiently accurate to verify that the sourceof the valve flow signal was the valve between the POS and the REFacoustic sensors.

The preferred method of determining whether or not a valve is completelyclosed is to take the ratio of the cross PSD of two sensors bracketingthe valve and compute the SNR and compare it to a threshold to obtain anacceptably low probability of false alarm (P_(FA)) and an acceptablyhigh probability of detection (P_(D)) against a flow rate set equal tothe flow rate or some fraction of the flow rate produced by thethreshold pressure drop used to declare an integrity problem. As acheck, the ratio of the PSDs for the two individual sensors can be used,or the difference in the coherence function for the test and thebackground noise. If there is a question about whether or not the valvebetween the two sensors is producing the valve flow signal, then thecoherence function and/or the bandpassed correlation function can beused to insure the valve is between the sensors. This should not be aproblem because γ² is determined from the cross PSD divided by theabsolute value of the product of the two individual PSDs to normalizethe cross PSD between 0 and 1.

A pre-amp is required, which may be included in the sensor or be astand-alone item. A power supply is also needed. A data acquisitionmeans, typically a micro-processor card, is used to collect the acousticdata. If the acoustic data is analog, then an A/D converter is needed. Acomputer or a special microprocessor can be used. If a specialmicroprocessor is used, the processing can be accomplished at the sensoritself. The data collected by the acoustic sensors can be communicatedto the computer by wireless or cable connection.

While certain representative embodiments and details have been shown forpurposes of illustrating the invention, it will be apparent to thoseskilled in the art that various changes in the methods and apparatusdisclosed herein may be made without departing from the scope of theinvention which is defined in the appended claims.

1. (canceled)
 2. A method for a valve flow test to determine whether avalve that needs to close completely to pressurize a piping systemcontaining a liquid and to hold pressure during a blowout preventer(BOP) system or subsystem test is completely closed, comprising thesteps of: (a) mounting at least one acoustic sensor on the valve of thepiping system or on one side of said valve, or mounting at least twoacoustic sensors that bracket said valve; (b) opening said valve so thatthe pressure is the same on both sides of the valve; (c) measuringbackground acoustic noise present at the valve when the pressure is thesame on both sides of the valve to obtain a background acoustic noisemeasurement; (d) closing said valve and pressurizing that portion of theBOP system or subsea system being tested to the pressure needed to testthe system; (e) measuring the acoustic valve flow signal plus backgroundnoise at the valve when the valve is intended to be fully closed toobtain an acoustic test result; and (f) determining if the valve isactually fully closed by detecting whether a difference exists betweensaid acoustic valve flow signal plus background noise measurement andthe background acoustic noise measurement, wherein no detecteddifference indicates the valve is fully closed, and a detecteddifference indicates the valve is not fully closed.
 3. The method ofclaim 2, where said acoustic valve test is made before, during, or afterthe completion of a BOP system test.
 4. The method of claim 2, were oneof more segments of the BOP or undersea system are tested.
 5. The methodof claim 2, where a constant pressure volumetric measurement system isused to determine whether said valve is closed.
 6. The method of claim2, where the volumetric flow rate is measured if said valve isincompletely closed.
 7. The method of claim 2, where a temporal orfrequency response from said acoustic sensor or acoustic sensors isdetermined by processing a times series of said acoustic valve flowsignal plus background noise measurements during said test to determineif fluctuations in said processed time series obtained when there is apressure difference across an incompletely closed valve is greater thanfluctuations in said processed time series obtained when said valve iscompletely closed.
 8. The method of claim 7, wherein a processing methodis selected from the group consisting of the direct comparison, theratio, or the difference of the times series, a statistic of the timeseries, or the power spectra computed when only one sensor is used, or across-power spectrum, correlation function, or coherence function whentwo sensors bracketing said valve collected are used during said test tosaid background noise to identify if a valve flow signal is present. 9.The method of claim 7, where the temporal or frequency response fromeach said acoustic sensor is measured and said processing of each saidacoustic sensor is accomplished using a system selected from the groupconsisting of an analog data collection and processing system, a digitaldata collection and processing system, and an analog data collectionsystem and with a digital processing system.
 10. The method of claim 7,where said temporal or frequency response from said processed timeseries is determined by processing said time series in one or morefrequency bands where a signal-to-noise ratio (SNR) of said valve flowsignal is sufficient to distinguish a valve flow signal from anincompletely closed valve from background noise and false alarms. 11.The method of claim 10, wherein the presence of an incompletely closedvalve is determined from the ratio of said cross-power spectrum obtainedduring said valve flow test and of said cross-power spectrum obtainedfrom a background test.
 12. The method of claim 10, where the presenceof said incompletely closed valve is determined from the ratio of saidpower spectrum obtained during said test and of said power spectrumobtained from a background test.
 13. The method of claim 10, where saidfrequency bands where said acoustic valve flow signal is strongest isdetermined from the output of the coherence function obtained duringsaid valve flow test and said background test, when two of said acousticsensors are used and where one of said acoustic sensors is mounted oneach side of said valve.
 14. The method of claim 13, where saidfrequency bands are determined from peaks in a magnitude-squared outputof the coherence function, γ², obtained during said test, which are notfound in the same frequency bands as a magnitude-squared output of thecoherence function of any interfering background noise that preventsdetection of an incompletely closed valve.
 15. The method of claim 13,where said frequency bands are determined from linear regions of thephase output of a coherence function, ϕ, obtained during said valve flowtest, which are not found in the same frequency bands as phase output ofthe coherence function of any interfering background noise that preventsdetection of an incompletely closed valve.
 16. The method of claim 13,where said frequency bands are determined from the output of thecoherence function and checked using the output of a correlationfunction.
 17. The method of claim 10, where said frequency bands areprocessed in said time series before any other processing is performed.18. The method of claim 10, where said frequency bands are processed inthe frequency functions generated from said time series.
 19. The methodof claim 7, where the background noise is obtained from the time seriesfrom at least one other acoustic sensor that is obtained when said valveflow signal is not present and said background noise time series is usedto remove said background noise from said time series of the valve flowsignal using standard noise cancellation methods and the presence ofsaid valve flow signal is determined from the difference between saidtime series of said valve flow acoustic sensor when no valve flow signalis present, where said other acoustic sensor could be the valve flowacoustic sensor when said valve flow signal is not present.
 20. Themethod of claim 19, where said time series of said background noise isused in an adaptive noise cancellation method to remove or minimize saidbackground acoustic noise in the said time series of said valve flowsignal acoustic sensor, where said background noise time series isobtained at the same time as said valve flow acoustic measurements. 21.The method of claim 19, where said time series of said background noiseis used to develop an average background noise cancellation transferfunction to remove or minimize said background acoustic noise in thesaid time series of said valve flow signal acoustic sensor, where saidbackground noise time series can be obtained before, during, or aftersaid valve flow acoustic measurements.